Document and Entity Information Document	9 Months Ended
Document and Entity Information Document	Sep. 30, 2018 shares
Document and Entity Information [Line Items]
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Entity Registrant Name	ALLETE INC
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	51,424,535
Entity Central Index Key	0000066756
Entity Tax Identification Number	410418150
Current Fiscal Year End Date	--12-31
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Current Reporting Status	Yes
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Amendment Flag	false

Consolidated Balance Sheet - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current Assets [Abstract]
Cash and Cash Equivalents	$ 128.0	$ 98.9
Accounts Receivable (Less Allowance of $2.6 and $2.1)	129.4	135.1
Inventories – Net	154.8	95.9
Prepayments and Other	27.2	37.6
Total Current Assets	439.4	367.5
Property, Plant and Equipment – Net	3,846.5	3,822.4
Regulatory Assets	370.6	384.7
Investment in ATC	126.0	118.7
Other Investments	51.7	53.1
Goodwill and Intangible Assets – Net	224.7	225.9
Other Non-Current Assets	104.4	107.7
Total Assets	5,163.3	5,080.0
Current Liabilities [Abstract]
Accounts Payable	131.8	136.3
Accrued Taxes	53.9	50.0
Accrued Interest	15.5	17.6
Long-Term Debt Due Within One Year	56.6	64.1
Other	144.9	83.2
Total Current Liabilities	402.7	351.2
Long-Term Debt	1,461.7	1,439.2
Deferred Income Taxes	231.3	230.5
Regulatory Liabilities	512.3	532.0
Defined Benefit Pension and Other Postretirement Benefit Plans	173.6	191.8
Other Non-Current Liabilities	265.6	267.1
Total Liabilities	3,047.2	3,011.8
Commitments, Guarantees and Contingencies (Note 13)
Shareholders’ Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 51.4 and 51.1 Shares Issued and Outstanding	1,421.1	1,401.4
Accumulated Other Comprehensive Loss	(27.3)	(22.6)
Retained Earnings	722.3	689.4
Total Shareholders’ Equity	2,116.1	2,068.2
Total Liabilities and Shareholders' Equity	$ 5,163.3	$ 5,080.0

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 2.6	$ 2.1
Common Stock [Abstract]
Common Stock, Par Value	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	51.4	51.1
Common Stock, Shares Issued	51.4	51.1

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenue [Abstract]
Contracts with Customers – Utility	$ 261.3	$ 277.6	$ 789.3	$ 824.1
Contracts with Customers – Non-utility	80.7	79.0	243.1	239.6
Other – Non-utility	6.0	5.9	17.9	17.7
Total Operating Revenue	348.0	362.5	1,050.3	1,081.4
Operating Expenses [Abstract]
Fuel, Purchased Power and Gas – Utility	103.2	93.5	300.6	283.2
Transmission Services – Utility	17.9	18.9	53.1	53.1
Cost of Sales – Non-utility	38.7	36.0	108.6	105.9
Operating and Maintenance	80.3	81.1	253.6	251.4
Depreciation and Amortization	51.5	50.9	153.4	151.5
Taxes Other than Income Taxes	13.1	14.1	43.8	42.7
Total Operating Expenses	304.7	294.5	913.1	887.8
Operating Income	43.3	68.0	137.2	193.6
Other Income (Expense) [Abstract]
Interest Expense	(17.6)	(16.6)	(51.6)	(50.5)
Equity Earnings in ATC	4.0	5.9	13.0	17.3
Other	1.4	1.8	5.7	5.0
Total Other Expense	(12.2)	(8.9)	(32.9)	(28.2)
Income Before Income Taxes	31.1	59.1	104.3	165.4
Income Tax Expense (Benefit)	0.4	14.2	(8.7)	34.6
Net Income	$ 30.7	$ 44.9	$ 113.0	$ 130.8
Average Shares of Common Stock [Abstract]
Basic (Shares)	51.4	51.0	51.3	50.7
Diluted (Shares)	51.6	51.2	51.5	50.9
Basic Earnings Per Share of Common Stock	$ 0.59	$ 0.88	$ 2.20	$ 2.58
Diluted Earnings Per Share of Common Stock	0.59	0.88	2.19	2.57
Dividends Per Share of Common Stock	$ 0.56	$ 0.535	$ 1.68	$ 1.605

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 30.7	$ 44.9	$ 113.0	$ 130.8
Other Comprehensive Income (Loss) [Abstract]
Currency Translation Adjustments	0.0	0.1	0.0	(0.1)
Unrealized Gain (Loss) on Securities Net of Income Tax Expense of $–, $0.1, $– and $0.6	0.0	0.1	(0.1)	0.8
Defined Benefit Pension and Other Postretirement Benefit Plans Net of Income Tax Expense of $0.1, $0.1, $0.3 and $0.4	0.3	0.2	1.0	0.6
Total Other Comprehensive Income	0.3	0.4	0.9	1.3
Total Comprehensive Income	$ 31.0	$ 45.3	$ 113.9	$ 132.1

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Unrealized Gain (Loss) on Securities, Income Tax Expense	$ 0.0	$ 0.1	$ 0.0	$ 0.6
Defined Benefit Pension and Other Postretirement Benefit Plans, Income Tax Expense	$ 0.1	$ 0.1	$ 0.3	$ 0.4

Consolidated Statement of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities [Abstract]
Net Income	$ 113.0	$ 130.8
AFUDC – Equity	(0.9)	(0.7)
Income from Equity Investments – Net of Dividends	(1.3)	(3.8)
Depreciation Expense	149.3	147.4
Amortization of PSAs	(17.9)	(17.7)
Amortization of Other Intangible Assets and Other Assets	7.8	7.6
Deferred Income Tax Expense	(9.1)	34.3
Share-Based and ESOP Compensation Expense	5.1	5.0
Defined Benefit Pension and Postretirement Benefit Expense	6.4	7.6
Provision for Interim Rate Refund	13.0	0.0
Provision for Tax Reform Refund	9.2	0.0
Bad Debt Expense	1.5	0.5
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	3.9	(9.6)
Inventories	(12.6)	5.3
Prepayments and Other	5.7	2.1
Accounts Payable	9.9	(2.6)
Other Current Liabilities	21.2	2.7
Cash Contributions to Defined Benefit Pension Plans	(15.0)	(1.7)
Changes in Regulatory and Other Non-Current Assets	7.2	23.9
Changes in Regulatory and Other Non-Current Liabilities	1.7	(23.9)
Cash from Operating Activities	298.1	307.2
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	9.3	5.2
Payments for Purchase of Available-for-sale Securities	(12.5)	(5.9)
Payments to Acquire Businesses, Net of Cash Acquired	0.0	17.4
Investment in ATC	(5.0)	(6.6)
Additions to Property, Plant and Equipment	(201.0)	(130.3)
Payments for (Proceeds from) Other Investing Activities	1.4	3.3
Cash for Investing Activities	(207.8)	(151.7)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	14.6	80.5
Proceeds from Issuance of Long-term Debt	72.7	131.5
Repayments of Long-Term Debt	(59.5)	(183.6)
Acquisition-Related Contingent Consideration Payments	0.0	(19.7)
Dividends on Common Stock	(86.2)	(81.4)
Other Financing Activities	(0.5)	(1.6)
Cash for Financing Activities	(58.9)	(74.3)
Change in Cash, Cash Equivalents and Restricted Cash	31.4	81.2
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 141.5	$ 119.5

Consolidated Statement of Shareholders' Equity - USD ($)
$ in Millions

Total

Retained Earnings [Member]

Accumulated Other Comprehensive Loss [Member]

Common Stock [Member]

Consolidated Statement of Shareholders' Equity [Roll Forward]

Adjustments to Opening Balances - Net of Income Taxes

^[1]

$ 0.5

$ 6.1

$ (5.6)

$ 0.0

Beginning Balance - Adjusted

2,068.7

695.5

(28.2)

1,401.4

Beginning Balance at Dec. 31, 2017

2,068.2

689.4

(22.6)

1,401.4

Comprehensive Income [Abstract]

Net Income

113.0

Other Comprehensive Income – Net of Tax [Abstract]

Unrealized Loss on Debt Securities

(0.1)

Defined Benefit Pension and Other Postretirement Plans

1.0

Total Comprehensive Income

113.9

Common Stock Issued

19.7

Dividends Declared

(86.2)

Ending Balance at Sep. 30, 2018

$ 2,116.1

$ 722.3

$ (27.3)

$ 1,421.1

[1]

Reflects the impacts associated with the adoption of accounting standards concerning Financial Instruments, Revenue from Contracts with Customers and the Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. (See Note 1. Operations and Significant Accounting Policies.)

Operations and Significant Accounting Policies

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Operations and Significant Accounting Policies [Text Block]

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Cash, Cash Equivalents and Restricted Cash. We consider all investments purchased with original maturities of three months or less to be cash equivalents. Restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet include collateral deposits required under an ALLETE Clean Energy loan agreement and U.S. Water Service’s standby letters of credit. The restricted cash amounts included in Other Non-Current Assets represent collateral deposits required under an ALLETE Clean Energy loan agreement and PSAs, and deposits from a SWL&P customer in aid of future capital expenditures. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amount presented in the Consolidated Statement of Cash Flows. During the first quarter of 2018, the Company updated the presentation of its Consolidated Statement of Cash Flows to include restricted cash with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. (See Recently Adopted Pronouncements - Statement of Cash Flows: Restricted Cash.)



Cash, Cash Equivalents and Restricted Cash	September 30, 2018		December 31, 2017		September 30, 2017		December 31, 2016
Millions
Cash and Cash Equivalents		$128.0		$98.9		$104.4		$27.5
Restricted Cash included in Prepayments and Other	4.8		2.6		6.5		2.2
Restricted Cash included in Other Non-Current Assets	8.7		8.6		8.6		8.6
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows		$141.5		$110.1		$119.5		$38.3

Inventories – Net. Inventories are stated at the lower of cost or net realizable value. Inventories in our Regulated Operations segment are carried at an average cost or first-in, first-out basis. Inventories in our U.S. Water Services and ALLETE Clean Energy segments, and Corporate and Other businesses are carried at an average cost, first-in, first-out or specific identification basis.



Inventories – Net	September 30, 2018			December 31, 2017
Millions
Fuel (a)		$27.3			$34.8
Materials and Supplies	44.0			46.5
Construction of Wind Energy Facility (b)	66.7			—
Raw Materials	3.1			2.8
Work in Progress	5.5			4.2
Finished Goods	9.0			8.3
Reserve for Obsolescence	(0.8		)	(0.7		)
Total Inventories – Net		$154.8			$95.9


(a)	Fuel consists primarily of coal inventory at Minnesota Power.


(b)	On February 28, 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification of the project costs from Property, Plant and Equipment – Net to Inventories – Net as ALLETE Clean Energy will not own the facility upon completion.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Non-Current Assets	September 30, 2018		December 31, 2017
Millions
Contract Assets (a)		$31.1		$31.6
Finance Receivable	10.4		11.0
Other	62.9		65.1
Total Other Non-Current Assets		$104.4		$107.7


(a)	Contract Assets include payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements as a reduction to revenue.



Other Current Liabilities	September 30, 2018		December 31, 2017
Millions
Provision for Interim Rate Refund (a)		$36.7	—
Contract Liabilities (b)	22.7			$8.7
PSAs	15.4		24.5
Provision for Tax Reform Refund (c)	9.2		—
Contingent Consideration (d)	5.7		—
Other	55.2		50.0
Total Other Current Liabilities		$144.9		$83.2


(a)	Provision for Interim Rate Refund is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $20.8 million of discounts provided to EITE customers that will be offset against interim rate refunds as of September 30, 2018 ($8.6 million as of December 31, 2017). (See Note 6. Regulatory Matters.)


(b)	Contract Liabilities include deposits received as a result of entering into contracts with our customers prior to completing our performance obligations.


(c)	Provision for Tax Reform Refund is expected to be refunded to Minnesota Power customers in the first quarter of 2019 and SWL&P customers in 2019 pending the outcome of SWL&P’s rate filing with the PSCW. (See Note 6. Regulatory Matters.)


(d)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 5. Fair Value.)



Other Non-Current Liabilities	September 30, 2018		December 31, 2017
Millions
Asset Retirement Obligation		$138.3		$122.7
PSAs	80.0		89.5
Contingent Consideration (a)	—		5.4
Other	47.3		49.5
Total Other Non-Current Liabilities		$265.6		$267.1


(a)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 5. Fair Value.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flows Information.



Nine Months Ended September 30,	2018		2017
Millions
Cash Paid for Interest – Net of Amounts Capitalized		$52.9		$51.4
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(14.4)			$1.2
Reclassification of Property, Plant and Equipment to Inventory (a)		$46.3	—
Capitalized Asset Retirement Costs		$15.4		$19.7
AFUDC–Equity		$0.9		$0.7
ALLETE Common Stock Contributed to the Pension Plans	—			$13.5


(a)	On February 28, 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification of the project costs from Property, Plant and Equipment – Net to Inventories – Net as ALLETE Clean Energy will not own the facility upon completion.

Subsequent Events. The Company performed an evaluation of subsequent events for potential recognition and disclosure through the date of the financial statements issuance.

Revenue.

Contracts with Customers – Utility includes sales from our regulated operations for generation, transmission and distribution of electric service, and distribution of water and gas services to our customers. Also included is an immaterial amount of regulated steam generation that is used by customers in the production of paper and pulp.

Contracts with Customers – Non-utility includes sales of goods and services to customers from ALLETE Clean Energy, U.S. Water Services and our Corporate and Other businesses.

Other – Non-utility is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices for PSAs that were assumed during the acquisition of various wind energy facilities.

Revenue Recognition

Revenue is recognized upon transfer of control of promised goods or services to our customers in an amount that reflects the consideration we expect to receive in exchange for those products or services. Revenue is recognized net of allowance for returns and any taxes collected from customers, which are subsequently remitted to the appropriate governmental authorities. We account for shipping and handling activities that occur after the customer obtains control of goods as a cost rather than an additional performance obligation thereby recognizing revenue at time of shipment and accruing shipping and handling costs when control transfers to our customers. We have a right to consideration from our customers in an amount that corresponds directly with the value to the customer for our performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.

Nature of Revenue Streams

Utility

Residential and Commercial includes sales for electric, gas or water service to customers, who have implied contracts with the utility, under rates governed by the MPUC, PSCW or FERC. Customers are billed on a monthly cycle basis and revenue is recognized for electric, gas or water service delivered during the billing period. Revenue is accrued for service provided but not yet billed at period end. Performance obligations with these customers are satisfied at time of delivery to customer meters and simultaneously consumed.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Municipal includes sales to 16 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. All wholesale electric contracts include a termination clause requiring a three-year notice to terminate. These contracts have termination dates ranging from 2019 through at least 2032, with a majority of contracts effective through at least 2024. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon municipal substation or meter.

Industrial includes sales recognized from contracts with customers in the taconite mining, iron concentrate, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 50 percent of total regulated utility kWh sales for the nine months ended September 30, 2018. Within industrial revenue, Minnesota Power has 9 Large Power Customer contracts, each serving requirements of 10 MW or more of customer load. These contracts automatically renew past the contract term unless a four-year advanced written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2022 through 2026. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $70 million per annum through 2019, $50 million in 2020 and 2021, $30 million in 2022 and $40 million for aggregate years thereafter, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts.

Other Power Suppliers includes the sale of energy under long-term PSAs with two customers as well as MISO market and liquidation sales. Expiration dates of these PSAs range from 2020 through 2026. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon delivery point defined in the contract (generally the MISO pricing node). Based on current contracts with two customers, we expect to recognize minimum revenue for fixed contract components of approximately $10 million per annum through 2019. Other power supplier contracts that extend beyond 2020 contain variable pricing components that prevent us from estimating future minimum revenue, and therefore are not included.

Other Revenue includes all remaining individually immaterial revenue streams for Minnesota Power and SWL&P, and is comprised of steam sales to paper and pulp mills, wheeling revenue and other sources. Revenue for steam sales to customers is recognized at the time steam is delivered and simultaneously consumed. Revenue is recognized at the time each performance obligation is satisfied.

Alternative Programs includes revenue that is driven by factors outside of our regulated entities’ control or as a result of the achievement of certain objectives, such as CIP financial incentives. This revenue is accounted for in accordance with the accounting standards for alternative revenue programs which allow for the recognition of revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows for automatic adjustment of future rates, the amount of revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. CIP financial incentives are recognized in the period in which the MPUC approves the filing, which is typically mid-year.

Non-utility

ALLETE Clean Energy

Long-term PSA revenue includes all sales recognized under long-term contracts for production, curtailment, capacity and associated renewable energy credits from ALLETE Clean Energy wind energy facilities. Expiration dates of these PSAs range from 2018 through 2032. Performance obligations for these contracts are satisfied at the time energy is delivered to an agreed upon point, or production is curtailed at the request of the customer, at specified prices. Revenue from the sale of renewable energy credits is recognized at the same time the related energy is delivered to the customer when sold to the same party.

Other is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices on assumed PSAs. As part of wind energy facility acquisitions, ALLETE Clean Energy assumed various PSAs that were above or below estimated market prices at the time of acquisition; the resulting differences between contract prices and estimated market prices are amortized to revenue over the remaining PSA term.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

U.S. Water Services

Point-in-time revenue is recognized for purchases by customers for chemicals, consumable equipment (e.g., filters, pumps and valves) or related maintenance and repair services as the customer’s usage and needs change over time. These goods and services are purchased on an as-needed basis by customers and therefore revenue can be variable. Products are shipped to the customer in accordance with the terms of the purchase order, and performance obligations are satisfied at the time of shipment of goods or when services are rendered to the customer.

Contract includes monthly revenue from contracts with customers to provide chemicals, consumable equipment and services to meet customer needs during the contract period. As agreed with the customer, a fixed amount is invoiced based on the goods and services to be provided under the contract. The duration of these contracts generally range in length from three months to five years and automatically renew. A 30-day notice is required to terminate such contracts without penalty after contract execution. Performance obligations are satisfied during the period as goods and service are delivered in accordance with the terms of the contract.

Capital Project includes the sale of equipment and other components assembled to create a water treatment system for a customer. These projects are provided under contracts at an agreed upon price to meet a customer's specifications and typically take less than one year to complete. In general, progress payments are received throughout the project period and are recorded as contract liabilities until performance obligations are satisfied at the time the equipment and other components are delivered to the customer’s site.

Corporate and Other

Long-term Contract encompasses the sale and delivery of coal to customer generation facilities. Revenue is recognized on a monthly basis at the cost of production plus a specified profit per ton of coal delivered to the customer. Coal sales are secured under long-term coal supply agreements extending through 2037. Performance obligations are satisfied during the period as coal is delivered to customer generation facilities.

Other primarily includes revenue from BNI Energy unrelated to coal, the sale of real estate from ALLETE Properties, and non‑rate base steam generation that is sold for use during production of paper and pulp. Performance obligations are satisfied when control transfers to the customer.

Payment Terms

Payment terms and conditions vary across our businesses. Aside from taconite-producing Large Power Customers, payment terms generally require payment to be made within 15 to 30 days from the end of the period that the service has been rendered or goods provided. In the case of its taconite-producing Large Power Customers, as permitted by the MPUC, Minnesota Power requires weekly payments for electric usage based on monthly energy usage estimates. These customers receive estimated bills based on Minnesota Power’s estimate of the customers’ energy usage, forecasted energy prices and fuel adjustment clause estimates. Minnesota Power’s taconite-producing Large Power Customers have generally predictable energy usage on a weekly basis and any differences that occur are trued-up the following month. Due to the timing difference of revenue recognition from the timing of invoicing and payment, the customer receives credit for the time value of money; however, we have determined that our contracts do not include a significant financing component as the period between when we transfer the service to the customer and when they pay for such service is minimal.

Assets Recognized From the Costs to Obtain a Contract with a Customer

We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of September 30, 2018, we have $31.1 million of assets recognized for costs incurred to obtain contracts with our customers ($31.6 million as of December 31, 2017). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. For the nine months ended September 30, 2018, and 2017, we recognized $1.9 million of non-cash amortization.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements.

Recently Adopted Pronouncements

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. In February 2018, the FASB issued an update allowing for a one-time reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the enactment of the TCJA. With the enactment of the new federal tax rates in 2017, entities were required to adjust deferred tax assets and liabilities to reflect the lower federal rate with the effect of this reduction impacting income from continuing operations in the period of enactment, even in instances where the related income tax effects of items were originally recognized in other comprehensive income. As such, companies were left with stranded tax effects in accumulated other comprehensive income that did not reflect the appropriate tax rate. This guidance is effective in the first quarter of 2019 with early adoption permitted. The Company elected to early adopt this guidance in the first quarter of 2018 which resulted in a reduction of $5.7 million to Accumulated Other Comprehensive Loss and a corresponding increase to Retained Earnings for the reclassification of the stranded income tax effects.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In March 2017, the FASB issued an accounting standard update to improve the presentation of net periodic pension and postretirement benefit costs. Under the guidance, an entity is required to present the service cost component of the net periodic benefit cost in the same income statement line as other employee compensation costs arising from services rendered during the period. The guidance also allows only the service cost component of the periodic cost to be eligible for capitalization on a prospective basis. The other components of net periodic expense must be presented separately from the line item that includes the service cost and must be excluded from the operating income subtotal. The Company adopted the guidance in the first quarter of 2018 and retrospectively adjusted the presentation of the service cost component and the other components of net periodic costs in the Consolidated Statement of Income. The retrospective adjustments for the quarter and nine months ended September 30, 2017, were as follows: Operating and Maintenance increased $1.1 million and $3.2 million, respectively, Cost of Sales – Non-utility decreased $0.1 million and $0.2 million, respectively, resulting in an increase of $1.0 million and $3.0 million, respectively to Other Income (Expense) – Other. There was no impact to net income as a result of adoption.

Financial Instruments. In 2016, the FASB issued an accounting standard update which requires entities to measure equity investments at fair value and recognize any changes in fair value in net income unless the investments qualify for the practicability exception. The practicability exception will be available for equity investments that do not have readily determinable fair values. The update was adopted by the Company in the first quarter of 2018 which resulted in a cumulative-effect transition adjustment reducing Retained Earnings by $0.1 million, including the tax effect, for the previously unrealized loss on available-for-sale equity securities in Accumulated Other Comprehensive Loss as of December 31, 2017.

Classification of Certain Cash Receipts and Cash Payments. In 2016, the FASB issued an accounting standard update which addressed the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero‑coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The amendments of this update were adopted by the Company in the first quarter of 2018. There was no impact to the Consolidated Statement of Cash Flows as a result of adoption.

Statement of Cash Flows: Restricted Cash. In 2016, the FASB issued an accounting standard update related to the presentation of restricted cash in the Company’s Consolidated Statement of Cash Flows. The update requires that the Consolidated Statement of Cash Flows explain the change during the period in cash, cash equivalents and restricted cash. Restricted cash should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. This guidance update was adopted by the Company in the first quarter of 2018 and was applied retrospectively to the periods presented in the Consolidated Statement of Cash Flows which resulted in a net increase in cash from financing activities of $4.3 million for the nine months ended September 30, 2017. Additional disclosure, including a reconciliation of the beginning-of-period and end-of-period cash on hand to the statement of cash flows, is included in this note. (See Cash, Cash Equivalents and Restricted Cash.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements (Continued)

Revenue from Contracts with Customers. In 2014, the FASB issued amended revenue recognition guidance that clarifies the principles for recognizing revenue from contracts with customers by providing a single comprehensive model to determine the measurement of revenue and timing of recognition. The guidance requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled to in exchange for those goods or services. The guidance requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures regarding customer contracts, significant judgments and changes in those judgments, and the assets recognized from the costs to obtain or fulfill a contract are required. The Company adopted this accounting guidance in the first quarter of 2018 and elected to apply the modified retrospective method of adoption to all contracts as of the date of initial application. The financial impact to the consolidated financial statements as a result of adoption of the new standard is immaterial. Based on the nature of the contracts with our customers and our related performance obligations which transfer control, a $0.5 million after-tax cumulative‑effect transition adjustment was made to increase the opening balance of Retained Earnings. We have included additional disclosures in the notes to the consolidated financial statements including additional information on the Company’s revenue streams and related performance obligations required to be satisfied in order to recognize revenue. (See Revenue Recognition.)

Practical Expedients

The following practical expedients were used by the Company as part of the adoption of the new revenue recognition guidance:


•	We have a right to consideration from our customers in an amount that corresponds directly with the value to such customer for performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.


•	We do not adjust the promised amount of consideration for the effects of a significant financing component as at contract inception we expect that the period between when we transfer a promised good or service to a customer and when the customer pays for that good or service will be one year or less.


•	Where applicable, we adopted this guidance using the portfolio approach in which contracts that have similar characteristics were reviewed as a portfolio. The effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying the guidance to each individual contract.


•	We recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that would otherwise have been recognized is one year or less.

Recently Issued Pronouncements

Simplifying the Test for Goodwill Impairment. In January 2017, the FASB issued updated guidance which simplifies the measurement of goodwill impairment by removing step two of the goodwill impairment test that requires the determination of the fair value of individual assets and liabilities of a reporting unit. The updated guidance requires goodwill impairment to be measured as the amount by which a reporting unit’s carrying value exceeds its fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This guidance is effective for the Company beginning in the first quarter of 2020, with early adoption permitted on a prospective basis.

Leases. In 2016, the FASB issued an accounting standard update which revises the existing guidance for leases. Under the revised guidance, lessees will be required to recognize a “right-of-use” asset and a lease liability for all leases with a term greater than 12 months. The new standard also requires additional quantitative and qualitative disclosures by lessees and lessors to enable users of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The accounting for leases by lessors and the recognition, measurement, and presentation of expenses and cash flows from leases are not expected to significantly change as a result of the new guidance. As of September 30, 2018, the Company has reviewed substantially all of its leases for its regulated businesses, completing the preliminary evaluations of the impact of this guidance. Our review and analysis of the Company’s energy infrastructure and related services and corporate and other businesses is nearly complete as well. Based on our preliminary assessment, we expect to recognize right-of-use assets and lease liabilities of approximately $65 million at adoption, which represents the discounted future minimum operating lease payments. The Company plans to adopt and implement the new guidance, utilizing the additional optional transition method and package of practical expedients, by recognizing a cumulative effect adjustment to retained earnings on the Consolidated Balance Sheet, if necessary, in the period of adoption. Management continues to evaluate the need for additional qualitative and quantitative disclosures to meet the requirements of the new standard following adoption. The revised guidance is effective for the Company beginning in the first quarter of 2019.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Income Taxes. Under SEC Staff Accounting Bulletin 118 (SAB 118), which was issued in December 2017, companies are allowed up to one year to complete the required analyses and accounting for the TCJA. SAB 118 requires companies to disclose which tax positions are considered complete, which tax positions are considered provisional and which tax provisions reflect prior law. At December 31, 2017, we were reasonably able to estimate the effects of the TCJA, and therefore recorded provisional amounts associated with the changes under the TCJA. The provisional amounts incorporated assumptions made based upon the Company’s interpretation of the TCJA. On August 21, 2018, the Internal Revenue Service provided initial guidance for handling changes surrounding the executive compensation deduction, which resulted in recording additional income tax expense of $0.9 million in the third quarter of 2018. The full-year additional income tax expense related to this guidance is expected to be $1.1 million. As the Company receives additional clarification and implementation guidance, any additional adjustments would be included in income from operations as an adjustment to income tax expense. The accounting for the TCJA is still considered provisional while we complete our analysis.

Consolidated Statement of Income. In the third quarter of 2018, we recognized a $4.4 million reduction in revenue for MISO rates that were billed in 2017 and are expected to be credited to customers in 2019. We have evaluated the effect of this out-of-period adjustment on the quarter and nine months ended September 30, 2018, as well as on the previous interim and annual periods in which they should have been recognized, and concluded that this adjustment is not material to any of the periods affected.

Investments

9 Months Ended

Sep. 30, 2018

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. As of September 30, 2018, the investment portfolio included the legacy real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held in other postretirement plans to fund employee benefits, the cash equivalents within these plans and other assets consisting primarily of land in Minnesota.



Other Investments	September 30, 2018		December 31, 2017
Millions
ALLETE Properties		$25.4		$26.4
Available-for-sale Securities (a)	21.0		19.1
Cash Equivalents	1.5		3.8
Other	3.8		3.8
Total Other Investments		$51.7		$53.1


(a)	As of September 30, 2018, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $1.8 million, in one year to less than three years was $3.5 million, in three years to less than five years was $1.9 million and in five or more years was $1.1 million.

Available-for-Sale Securities. We account for our available-for-sale securities portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits. Gross realized and unrealized gains and losses on our available-for-sale securities were immaterial for the quarter and nine months ended September 30, 2018, and 2017.

Acquisitions

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Acquisitions [Text Block]

ACQUISITIONS

The following acquisition is consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its regulated businesses, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. The pro forma impact of the following acquisition was not significant to the results of the Company for the nine months ended September 30, 2018, and 2017.

2017 Activity.

Tonka Water. In September 2017, U.S. Water Services acquired 100 percent of Tonka Water. Total consideration for the transaction was $19.2 million, including a working capital adjustment. Consideration of $19.0 million was paid in cash on the acquisition date and a working capital adjustment of $0.2 million was paid in the fourth quarter of 2017. Tonka Water is a supplier of municipal and industrial water treatment systems that expands U.S. Water Services’ geographic and customer markets.

NOTE 3. ACQUISITIONS (Continued)

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2018, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.



Millions
Assets Acquired
Accounts Receivable		$5.1
Other Current Assets	5.1
Trade Names (a)	0.9
Goodwill (a)(b)	16.9
Other Non-Current Assets	0.2
Total Assets Acquired		$28.2
Liabilities Assumed
Current Liabilities		$9.0
Total Liabilities Assumed		$9.0
Net Identifiable Assets Acquired		$19.2

(a) Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 4. Goodwill and Intangible Assets.)


(b)	Recognized goodwill is attributable to the assembled workforce and anticipated synergies. For tax purposes, the purchase price allocation resulted in $4.1 million of deductible goodwill.

Acquisition-related costs were immaterial, expensed as incurred during 2017 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

Goodwill and Intangible Assets

9 Months Ended

Sep. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The aggregate carrying amount of goodwill was $148.5 million as of September 30, 2018, and $148.3 million as of December 31, 2017.

Balances of intangible assets, net, excluding goodwill as of September 30, 2018, are as follows:



	December 31, 2017		Additions		Amortization	September 30, 2018
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships		$54.7		$0.2	$(3.2)		$51.7
Developed Technology and Other (a)	6.3		2.5		(0.9)	7.9
Total Definite-Lived Intangible Assets	61.0		2.7		(4.1)	59.6
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$77.6		$2.7	$(4.1)		$76.2


(a)	Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.

Customer relationships have a remaining useful life of approximately 19 years, and developed technology and other have remaining useful lives ranging from less than 1 year to approximately 10 years (weighted average of approximately 6 years). The weighted average remaining useful life of all definite-lived intangible assets as of September 30, 2018, is approximately 18 years.

NOTE 4. GOODWILL AND INTANGIBLE ASSETS (Continued)

Amortization expense for intangible assets was $1.4 million and $4.1 million for the quarter and nine months ended September 30, 2018, respectively ($1.3 million and $4.1 million for the quarter and nine months ended September 30, 2017, respectively). Accumulated amortization was $18.9 million as of September 30, 2018 ($14.8 million as of December 31, 2017). The estimated amortization expense for definite-lived intangible assets for the remainder of 2018 is $1.5 million. Estimated annual amortization expense for definite‑lived intangible assets is $5.3 million in 2019, $4.9 million in 2020, $4.9 million in 2021, $4.6 million in 2022 and $38.4 million thereafter.

Fair Value

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value [Text Block]

FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Descriptions of the three levels of the fair value hierarchy are discussed in Note 9. Fair Value to the Consolidated Financial Statements in our 2017 Form 10-K.

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2018, and December 31, 2017. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables.



	Fair Value as of September 30, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$12.7	—		—			$12.7
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.3	—		8.3
Cash Equivalents	1.5		—		—		1.5
Total Fair Value of Assets		$14.2		$8.3	—			$22.5

Liabilities
Deferred Compensation (b)	—			$20.5	—			$20.5
U.S. Water Services Contingent Consideration (c)	—		—			$5.7	5.7
Total Fair Value of Liabilities	—			$20.5		$5.7		$26.2
Total Net Fair Value of Assets (Liabilities)		$14.2	$(12.2)		$(5.7)		$(3.7)


(a)	Included in Other Investments on the Consolidated Balance Sheet.


(b)	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.


(c)	Included in Other Current Liabilities on the Consolidated Balance Sheet.

NOTE 5. FAIR VALUE (Continued)



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$10.2	—		—			$10.2
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.9	—		8.9
Cash Equivalents	3.8		—		—		3.8
Total Fair Value of Assets		$14.0		$8.9	—			$22.9

Liabilities (b)
Deferred Compensation	—			$18.2	—			$18.2
U.S. Water Services Contingent Consideration	—		—			$5.4	5.4
Total Fair Value of Liabilities	—			$18.2		$5.4		$23.6
Total Net Fair Value of Assets (Liabilities)		$14.0	$(9.3)		$(5.4)		$(0.7)


(a)	Included in Other Investments on the Consolidated Balance Sheet.


(b)	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

The Level 3 liability in the preceding tables is the result of the 2015 acquisition of U.S. Water Services. Changes in the U.S. Water Services Contingent Consideration can result from modifications to the shareholder agreement, changes in discount rates, timing of milestones that trigger payment, or the timing and amount of earnings estimates. The following table provides a reconciliation of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of September 30, 2018. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate.



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2017		$5.4
Accretion	0.3
Balance as of September 30, 2018		$5.7

For the nine months ended September 30, 2018, and the year ended December 31, 2017, there were no transfers in or out of Levels 1, 2 or 3.

Fair Value of Financial Instruments. With the exception of the item listed in the following table, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed in the following table was based on quoted market prices for the same or similar instruments (Level 2).



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Long-Term Debt Due Within One Year
September 30, 2018	$1,527.9	$1,557.6
December 31, 2017	$1,513.3	$1,627.6

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-financial assets such as equity method investments, goodwill, intangible assets, land inventory, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized. For the quarter and nine months ended September 30, 2018, and the year ended December 31, 2017, there were no triggering events or indicators of impairment for these non-financial assets.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Regulatory Matters

9 Months Ended

Sep. 30, 2018

Regulated Operations [Abstract]

Regulatory Matters [Text Block]

REGULATORY MATTERS

Regulatory matters are summarized in Note 4. Regulatory Matters to our Consolidated Financial Statements in our 2017 Form 10‑K, with additional disclosure provided in the following paragraphs.

Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, PSCW or FERC. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable, and environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Environmental Improvement Rider.) Revenue from cost recovery riders was $29.1 million and $81.2 million for the quarter and nine months ended September 30, 2018, respectively ($23.1 million and $71.7 million for the quarter and nine months ended September 30, 2017, respectively).

2016 Minnesota General Rate Case. In November 2016, Minnesota Power filed a retail rate increase request with the MPUC which sought an average increase of approximately 9 percent for retail customers. The rate filing sought a return on equity of 10.25 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $55 million in additional revenue. In December 2016, Minnesota Power filed a request to modify its original interim rate proposal, reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7 million beginning in January 2017.

In February 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an April 2017 order, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning in May 2017. As a result of working with intervenors and further developments as the rate review progressed, Minnesota Power’s final rate request was adjusted to approximately $49 million on an annualized basis. In an order dated March 12, 2018, the MPUC affirmed determinations made at a hearing on January 18, 2018, regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Upon commencement of final rates, we expect additional revenue of approximately $13 million on an annualized basis. Final rates are expected to commence in the fourth quarter of 2018; interim rates will be collected through this period which are fully offset by the recognition of a corresponding reserve. Minnesota Power has recorded a reserve for an interim rate refund of $57.5 million as of September 30, 2018 ($32.3 million as of December 31, 2017). The MPUC also disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in the fourth quarter of 2017.

As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million in the fourth quarter of 2017.

On April 2, 2018, Minnesota Power filed a petition with the MPUC requesting reconsideration of certain decisions in the MPUC’s order dated March 12, 2018, collectively representing approximately $20 million to $25 million in additional revenue on an annualized basis. Minnesota Power’s petition included requesting reconsideration of the allowed return on common equity, recovery of the prepaid pension asset in rate base, certain disallowed expenses, and certain transmission revenue adjustments. In an order dated May 29, 2018, the MPUC denied Minnesota Power’s petition for reconsideration and accepted a Minnesota Department of Commerce request for reconsideration reducing the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 while utilizing the benefits of the lower federal income tax rate enacted as part of the TCJA to mitigate the impact on customer rates.

Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015, which established a Minnesota energy policy to have competitive rates for certain industries such as mining and forest products. In 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. In a March 2016 order, the MPUC dismissed the petition without prejudice. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The rate adjustments were intended to be revenue and cash flow neutral to Minnesota Power. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an April 2017 order; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism, with the subsequent order issued in October 2017 that modified the April 2017 order. During 2017, Minnesota Power provided discounts of $8.6 million that were recorded as a regulatory asset.

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

In September 2017, Minnesota Power informed its EITE customers that it had suspended the EITE discount due to a concern that it was not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing in September 2017, as well as the interim rate reduction and decisions in its 2016 general rate case. Based on the MPUC’s decisions at a hearing on January 18, 2018, as part of Minnesota Power’s 2016 general rate case, Minnesota Power reinstated the EITE discount effective January 1, 2018. Minnesota Power expects the discount to EITE customers to be approximately $15 million annually based on EITE customer current operating levels. While interim rates are in effect for Minnesota Power’s 2016 general rate case, discounts provided to EITE customers will offset interim rate refund reserves for non-EITE customers. Minnesota Power provided $4.1 million and $12.2 million of discounts to EITE customers during the quarter and nine months ended September 30, 2018, respectively ($2.7 million and $8.6 million for the quarter and nine months ended September 30, 2017, respectively).

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. All wholesale contracts include a termination clause requiring a three-year notice to terminate.

Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission is effective through at least December 31, 2032. No termination notice may be given for this contract prior to July 1, 2029. The wholesale electric service contracts with SWL&P and another municipal customer are effective through at least November 30, 2021, and through June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided termination notice for its contract in 2016. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. The rates included in these three contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to Minnesota Power’s authorized rate of return for Minnesota retail customers. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.

Minnesota Power’s wholesale electric contracts with 14 municipal customers are effective through varying dates ranging from 2024 through 2029. No termination notices may be given prior to three years before maturity. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will be determined using a cost-based formula methodology with limits on the annual change from the previous year’s capacity charge. The base energy charge for each year of the contract term will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider for certain transmission investments and expenditures. In a 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates allowing Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. As a result of the MPUC approval of the certificate of need for the GNTL in 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with a subsidiary of Manitoba Hydro (see Great Northern Transmission Line), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission bill factor filings.

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider for investments and expenditures related to Bison. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of certain renewable investments plus a return on the capital invested. Updated customer billing rates for the renewable cost recovery rider were provisionally approved by the MPUC in an order dated July 30, 2018, subject to further review by the MPUC.

Minnesota Power also has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. (See Minnesota Solar Energy Standard.) Currently, there is no approved customer billing rate for solar costs.

In a December 2017 order, the MPUC modified a November 2016 order to allow Minnesota Power to account for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. As a result of the favorable regulatory outcome, Minnesota Power recorded a reduction in its regulatory liability and an increase in Operating Revenue of $14.3 million in the third quarter of 2017. The North Dakota investment tax credits previously recorded were reestablished as income tax credits in Corporate and Other, resulting in a $7.9 million increase to net income in the third quarter of 2017.

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were provisionally approved by the MPUC in an order dated June 20, 2018, subject to further review by the MPUC.

Fuel Adjustment Clause Reform. In a December 2017 order, the MPUC adopted a program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The order will change the method of accounting for all Minnesota electric utilities to a monthly budgeted, forward-looking FAC with an annual prudence review and true-up to actual allowed costs. The MPUC is seeking input from Minnesota electric utilities and other stakeholders on the implementation and transition accounting needed to adopt the change. At a hearing on September 20, 2018, the MPUC deferred the implementation date to January 1, 2020.

Tax Cuts and Jobs Act of 2017. In December 2017, the MPUC opened a docket to review the effects of the TCJA on electric and natural gas rates and services in Minnesota, including the legislation’s impact on tax rates and utilities’ deferred income tax assets and liabilities. On March 2, 2018, Minnesota Power submitted an initial filing to the MPUC regarding the impacts of the TCJA on Minnesota Power. As part of Minnesota Power’s rate case, in an order dated May 29, 2018, the MPUC directed Minnesota Power to utilize the benefits of the lower federal income tax rate enacted as part of the TCJA to offset an increase in depreciation expense, effective January 1, 2018, resulting from the reduction in the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 that would have otherwise resulted in an increase in customer rates. The impact of the TCJA on Minnesota Power’s deferred income tax assets and liabilities was not addressed in the rate case order.

At a hearing on August 9, 2018, the MPUC determined the regulatory treatment for the impact of the TCJA on Minnesota Power’s deferred income tax assets and liabilities. The MPUC authorized Minnesota Power to amortize the income tax benefits from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA primarily over the life of the related property, plant and equipment with the remainder amortized over a 10 year period. The MPUC directed Minnesota Power to begin refunding these income tax benefits as a monthly bill credit at the same time it implements final rates in its 2016 general rate case. Additionally, Minnesota Power customers will receive a one-time bill credit in 2019 for the income tax benefits amortized from January 1, 2018, through the date when final rates become effective.

On January 10, 2018, the PSCW opened a docket to review the effects of the TCJA and directed Wisconsin utilities to defer its impacts until further direction was provided by the PSCW. On February 9, 2018, SWL&P filed comments with the PSCW regarding the impacts of the TCJA on SWL&P. In this filing, SWL&P proposed deferring the benefits of the TCJA and incorporating any deferred refunds or credits into its next general rate case. In an order dated May 24, 2018, the PSCW directed SWL&P to refund the benefits of the lower federal income tax rates enacted as part of the TCJA on customer bills beginning in July 2018. Any changes in deferred income taxes will be adjusted as part of SWL&P’s rate filing. (See 2018 Wisconsin General Rate Case.)

2016 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a 2017 PSCW retail rate order effective August 2017 that allows for a 10.5 percent return on common equity and a 55 percent equity ratio. SWL&P’s retail rates prior to August 2017 were based on a 2012 PSCW retail rate order that provided for a 10.9 percent return on equity. On an annualized basis, SWL&P expects to collect additional revenue of $2.5 million under the 2017 PSCW retail rate order.

2018 Wisconsin General Rate Case. On May 25, 2018, SWL&P filed a rate increase request with the PSCW requesting an average increase of 2.7 percent for retail customers (2.0 percent increase in electric rates; 2.3 percent increase in natural gas rates; and 8.3 percent increase in water rates). The filing seeks an overall return on equity of 10.5 percent and a 55.41 percent equity ratio. On an annualized basis, the filing requested additional revenue of approximately $2.4 million. SWL&P anticipates new rates will go into effect in the first quarter of 2019. We cannot predict the level of rates that may be approved by the PSCW.

NOTE 6. REGULATORY MATTERS (Continued)

Integrated Resource Plan. In 2015, Minnesota Power filed its 2015 IRP with the MPUC, which included an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. The 2015 IRP also contained steps in Minnesota Power’s EnergyForward strategic plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between 200 MW and 300 MW of natural gas-fired generation in the next decade. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for Taconite Harbor, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. In 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired, which is expected to occur in the fourth quarter of 2018.

In July 2017, Minnesota Power submitted a resource package to the MPUC requesting approval of PPAs for the output of a 250 MW wind energy facility and a 10 MW solar energy facility as well as approval of a 250 MW natural gas energy PPA. These agreements are subject to MPUC approval of the construction of NTEC, a 525 MW to 550 MW combined-cycle natural gas‑fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. In a September 2017 order, the MPUC approved Minnesota Power’s request that approval for the natural gas energy PPA be decided through a contested case process. On July 2, 2018, an administrative law judge issued a recommendation that the MPUC deny approval of the NTEC agreements; the recommendation is not binding on the MPUC. On July 23, 2018, Minnesota Power filed exceptions to the administrative law judge’s recommendation. At a hearing on October 29, 2018, the MPUC approved Minnesota Power’s request for approval of the NTEC agreements. Separately, the MPUC required a baseload retirement evaluation in Minnesota Power’s next IRP filing analyzing its existing fleet including potential early retirement scenarios of Boswell Units 3 and 4, including a securitization plan. The MPUC also approved Minnesota Power’s request to extend the next IRP filing deadline until October 1, 2020.

On June 18, 2018, Minnesota Power filed a separate petition for approval of the PPA for the output of the 10 MW solar energy facility to be located in central Minnesota, which was approved by the MPUC in an order dated October 2, 2018. On August 22, 2018, Minnesota Power filed a separate petition for approval of an amended PPA for the output of the 250 MW wind energy facility to be located in southwestern Minnesota.

Great Northern Transmission Line. Minnesota Power is constructing the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro. In 2015, a certificate of need was approved by the MPUC. Based on this approval, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Transmission Cost Recovery Rider.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In a 2016 order, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing, and in 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre‑construction activities commenced in the first quarter of 2017 with construction expected to be completed in 2020. To date, most of the right-of-way has been cleared while foundation installation and transmission tower construction have commenced. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, of which Minnesota Power’s portion is expected to be between $300 million and $350 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $314.9 million have been incurred through September 30, 2018, of which $163.3 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to the MMTP, a new transmission line in Canada that will connect with the GNTL. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the MMTP to the Manitoba Conservation and Water Stewardship for siting and environmental approval, which remains pending. In 2016, Manitoba Hydro filed an application with the Canadian National Energy Board (NEB) requesting authorization to construct and operate the MMTP. The NEB determined that Manitoba Hydro’s application was complete in December 2017, and held public hearings in June 2018. The NEB is required to make a decision on the MMTP by March 2019, but is not precluded from making a decision prior to that date. Approval of the Canadian federal cabinet is also required.

NOTE 6. REGULATORY MATTERS (Continued)

Great Northern Transmission Line (Continued)

The MMTP is subject to legal and regulatory challenges which Minnesota Power is actively monitoring. Manitoba Hydro has informed Minnesota Power that it continues to work towards completing the MMTP on schedule. In order to meet the transmission in‑service requirements in PPAs with Minnesota Power, Manitoba Hydro has indicated that it would need to start construction of the MMTP by December 2018. We are unable to predict the outcome of the Canadian regulatory review process, including the timing thereof or whether any onerous conditions may be imposed, or the timing of the completion of the MMTP, including the impact of any delays that may result in construction schedule adjustments. Any significant delays in the MMTP construction schedule may result in Minnesota Power adjusting the GNTL construction schedule and impact the timing of capital expenditures and associated cost recovery under our transmission cost recovery rider.

Construction of Manitoba Hydro’s Keeyask hydroelectric generation facility, which will provide the power to be sold under PPAs with Minnesota Power and transmitted on the MMTP and the GNTL, commenced in 2014 and is anticipated to be in service by early 2021.

Conservation Improvement Program. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on energy CIPs each year. On April 2, 2018, Minnesota Power submitted its 2017 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $3.0 million based upon MPUC procedures. In an order dated September 4, 2018, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive which was recorded as revenue and as a regulatory asset in the third quarter of 2018. In 2017, the CIP financial incentive of $5.5 million was recognized in the second quarter upon approval by the MPUC of Minnesota Power’s 2016 CIP consolidated filing in a June 2017 order. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

MISO Return on Equity Complaint. MISO transmission owners, including ALLETE and ATC, have an authorized return on equity of 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization.

In 2016, a federal administrative law judge ruled on a complaint proposing a reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is pending, which is not expected to have a material impact on our Consolidated Financial Statements.

Minnesota Solar Energy Standard. Minnesota law requires at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less and community solar garden subscriptions. In a 2016 order, the MPUC approved Camp Ripley, a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligible to meet the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a 2016 order, the MPUC approved a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. In an order dated October 2, 2018, the MPUC approved a PPA for the output of the 10 MW Blanchard solar energy facility to be located in central Minnesota. Minnesota Power believes Camp Ripley, the community solar garden arrays, and the PPA for the output of the 10 MW Blanchard solar energy facility will meet approximately two‑thirds of the overall mandate. Additionally, in a February 2017 order, the MPUC approved Minnesota Power’s proposal to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. The proposal to incentivize customer‑sited solar installations and community solar garden subscriptions is expected to meet a portion of the required small scale solar mandate.

Regulatory Assets and Liabilities. Our regulated utility operations are subject to accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. No regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.

NOTE 6. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	September 30, 2018		December 31, 2017
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans		$214.0		$220.3
Income Taxes	107.9		112.8
Asset Retirement Obligations	31.9		29.6
Manufactured Gas Plant	8.0		8.1
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	—		3.3
Other	3.8		5.6
Total Non-Current Regulatory Assets		$370.6		$384.7

Current Regulatory Liabilities (a)
Provision for Interim Rate Refund (b)		$36.7	—
Provision for Tax Reform Refund (c)	9.2		—
Transmission Formula Rates	4.4		—
Total Current Regulatory Liabilities	50.3		—
Non-Current Regulatory Liabilities
Income Taxes	398.1			$411.2
Wholesale and Retail Contra AFUDC	62.0		57.9
Plant Removal Obligations	24.1		20.3
North Dakota Investment Tax Credits	14.6		14.1
Cost Recovery Riders	11.0		2.2
Conservation Improvement Program	1.1		—
Provision for Interim Rate Refund (b)	—		23.7
Other	1.4		2.6
Total Non-Current Regulatory Liabilities	512.3		532.0
Total Regulatory Liabilities		$562.6		$532.0


(a)	Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.


(b)	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $20.8 million of discounts provided to EITE customers as of September 30, 2018, that will be offset against interim rate refunds ($8.6 million as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)

(c)

Provision for Tax Reform Refund is expected to be refunded to Minnesota Power customers in the first quarter of 2019 and SWL&P customers in 2019 pending the outcome of SWL&P’s rate filing with the PSCW. (See Tax Cuts and Jobs Act of 2017.)

Investment in ATC

9 Months Ended

Sep. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Investment in ATC [Text Block]

INVESTMENT IN ATC

Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. As of September 30, 2018, our equity investment in ATC was $126.0 million ($118.7 million at December 31, 2017). In the first nine months of 2018, we invested $5.0 million in ATC, and on October 31, 2018, we invested an additional $1.2 million. We expect to make no additional investments in 2018.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2017		$118.7
Cash Investments	5.0
Equity in ATC Earnings	13.0
Distributed ATC Earnings	(11.7		)
Amortization of the Remeasurement of Deferred Income Taxes (a)	1.0
Equity Investment Balance as of September 30, 2018		$126.0

(a) Amortization related to the impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

NOTE 7. INVESTMENT IN ATC (Continued)

ATC’s authorized return on equity is 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization.

Short-Term and Long-Term Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Short-Term and Long-Term Debt [Text Block]

SHORT-TERM AND LONG-TERM DEBT

The following tables present the Company’s short-term and long-term debt as of September 30, 2018, and December 31, 2017:



September 30, 2018	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt		$57.0	$(0.4)		$56.6
Long-Term Debt	1,470.9		(9.2)	1,461.7
Total Debt		$1,527.9	$(9.6)		$1,518.3



December 31, 2017	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt		$64.6	$(0.5)		$64.1
Long-Term Debt	1,448.7		(9.5)	1,439.2
Total Debt		$1,513.3	$(10.0)		$1,503.3

On April 16, 2018, ALLETE issued and sold $60.0 million of its First Mortgage Bonds (the Bonds) that bear interest at 4.07 percent. The Bonds will mature in April 2048 and pay interest semi-annually in April and October of each year, commencing on October 16, 2018. ALLETE has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. ALLETE intends to use the proceeds from the sale of the Bonds to fund utility capital investment and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

On October 3, 2018, and October 17, 2018, ALLETE repaid $20.0 million and $10.0 million, respectively, under an unsecured term loan due in 2020.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of September 30, 2018, our ratio was approximately 0.42 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of September 30, 2018, ALLETE was in compliance with its financial covenants.

Income Tax Expense

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
Millions
Current Income Tax Expense (a)
Federal	—			—			—			—
State	—				$0.1			$0.4			$0.3
Total Current Income Tax Expense	—				$0.1			$0.4			$0.3
Deferred Income Tax Expense (Benefit)
Federal (b)	$(2.2)				$9.2		$(16.4)				$20.3
State	2.8			5.0			7.8			14.5
Investment Tax Credit Amortization	(0.2		)	(0.1		)	(0.5		)	(0.5		)
Total Deferred Income Tax Expense (Benefit)		$0.4			$14.1		$(9.1)				$34.3
Total Income Tax Expense (Benefit)		$0.4			$14.2		$(8.7)				$34.6


(a)	For the quarter and nine months ended September 30, 2018, and 2017, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.


(b)	For the quarter and nine months ended September 30, 2018, the federal tax benefit is primarily due to the reduction of the federal statutory tax rate from 35 percent to 21 percent enacted as part of the TCJA and production tax credits.

The Company's tax provision for interim periods is determined using an estimate of its annual effective tax rate, adjusted for discrete items arising in that quarter. In each quarter, the Company updates its estimate of the annual effective tax rate and if the estimated annual effective tax rate changes, the Company would make a cumulative adjustment in that quarter.



	Quarter Ended						Nine Months Ended
Reconciliation of Taxes from Federal Statutory	September 30,						September 30,
Rate to Total Income Tax Expense	2018			2017			2018			2017
Millions
Income Before Non-Controlling Interest and Income Taxes		$31.1			$59.1			$104.3			$165.4
Statutory Federal Income Tax Rate	21		%	35		%	21		%	35		%
Income Taxes Computed at Statutory Federal Rate		$6.5			$20.7			$21.9			$57.9
Increase (Decrease) in Income Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	2.2			3.3			6.4			9.6
Production Tax Credits	(9.4		)	(10.4		)	(35.0		)	(33.4		)
Regulatory Differences – Excess Deferred Tax	(1.1		)	0.3			(5.5		)	1.0
Other	2.2			0.3			3.5			(0.5		)
Total Income Tax Expense (Benefit)		$0.4			$14.2		$(8.7)				$34.6

For the nine months ended September 30, 2018, the effective tax rate was a benefit of 8.3 percent (expense of 20.9 percent for the nine months ended September 30, 2017). The decrease from 2017 was primarily due to the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA and lower pre-tax income.

Uncertain Tax Positions. As of September 30, 2018, we had gross unrecognized tax benefits of $1.7 million ($1.7 million as of December 31, 2017). Of the total gross unrecognized tax benefits, $0.8 million represents the amount of unrecognized tax benefits included on the Consolidated Balance Sheet that, if recognized, would favorably impact the effective income tax rate. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.

ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE has no open federal or state audits, and is no longer subject to federal examination for years before 2015, or state examination for years before 2013.

Reclassifications Out of Accumulated Other Comprehensive Loss	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Reclassifications Out of Accumulated Other Comprehensive Income (Loss) [Text Block]	RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE LOSS Changes in Accumulated Other Comprehensive Loss. Comprehensive income (loss) is the change in shareholders’ equity during a period from transactions and events from non-owner sources, including net income. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses on available-for-sale debt securities and defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits. For the quarter and nine months ended September 30, 2018, and 2017, reclassifications out of accumulated other comprehensive loss for the Company were not material. Changes in accumulated other comprehensive loss for the nine months ended September 30, 2018, are presented on the Consolidated Statement of Shareholders’ Equity.

Earnings Per Share and Common Stock	9 Months Ended
Earnings Per Share and Common Stock	Sep. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share and Common Stock [Text Block]